Depth-based borehole trajectory control

ABSTRACT

Methods and apparatuses for controlling a trajectory of a borehole being drilled into the earth are provided. The apparatus includes a drilling system including a drill tubular, a disintegrating device, and a steering system coupled to the drill tubular configured to steer the drilling system, the drilling system configured to drill the borehole by receiving control outputs from at least one control unit for controlling parameters of the drilling system, the at least one control unit configured to provide the control outputs to the steering system, the at least one control unit being configured to provide a depth-based control output.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Continuation of U.S. application Ser. No.15/171,193, filed Jun. 2, 2016, the disclosure of which is incorporatedby reference herein in its entirety.

BACKGROUND

Boreholes are drilled into the earth for many purposes such ashydrocarbon production, geothermal production, and carbon dioxidesequestration. Many of these boreholes need to have a precise locationand geometry in order to increase efficiency for its desired purpose.Steam assisted gravity drainage is one example of a specific horizontalgeometry for efficient hydrocarbon production. The geometry generallyincludes, for example, depth or drilled distance, inclination, build-uprate, and azimuth. The location may relate to a distance to a geologicformation boundary and/or a distance to an adjacent borehole. Hence,development of drilling control systems to increase the accuracy andprecision of drilling boreholes would be well received in the drillingindustry.

BRIEF SUMMARY

Methods and apparatuses for controlling a trajectory of a borehole beingdrilled into the earth are provided. The apparatus includes a drillingsystem comprising a drill tubular, a disintegrating device, and asteering system coupled to the drill tubular configured to steer thedrilling system, the drilling system configured to drill the borehole byreceiving control outputs for controlling parameters of the drillingsystem and at least one control unit configured to provide the controloutputs to the steering system, the at least one control unit beingconfigured to provide depth-based control.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way.With reference to the accompanying drawings, like elements are numberedalike:

FIG. 1A depicts aspects of a drilling system for drilling a boreholeinto the earth;

FIG. 1B depicts a schematic illustration of a control process that maybe employed by embodiments of the present disclosure;

FIG. 2 depicts aspects of a trajectory vector for representing atrajectory of the borehole being drilled;

FIG. 3 depicts aspects of one embodiment of controller implementationfor controlling drilling parameters;

FIG. 4 depicts aspects of one embodiment of controller implementationusing a formation evaluation sensor;

FIG. 5 depicts aspects of one embodiment of controller implementationproviding drilling trajectory control;

FIG. 6 depicts aspects of one embodiment of controller implementationproviding downhole control;

FIG. 7 depicts aspects of one embodiment of controller implementationusing a fixed reference value;

FIG. 8 depicts aspects of pre-control and pre-filter using a knowntarget trajectory;

FIG. 9 depicts aspects of model predictive control using a drill-aheadmodel of the drilling system; and

FIG. 10 is a flow chart for a method for controlling a trajectory of aborehole being drilled into the earth.

DETAILED DESCRIPTION

A description of one or more embodiments of the disclosed apparatusesand methods are presented herein by way of illustration and example andare not intended to be limitations. Reference will be made to theappended to the figures.

Disclosed are apparatus and method for drilling a borehole into theearth. The method, which is implemented by the apparatus describedherein or other controller, computer, and/or processor, provides acontrol approach that can be used to control a borehole trajectory thatmay be characterized, for example, by depth, drilled distance,inclination, azimuth, build-up-rate, distance to a formation boundary,distance to an object such as another borehole, a geologic object, adownhole installation, or any other borehole trajectory relatedparameter. As used herein, the term “depth” may be considered to beinclusive of data indicative of depth, such as “drilled distance” (alsoknown as “measured depth”), true vertical depth, true stratigraphicaldepth in order to account for deviated or horizontal boreholes, or anyother depth related data including depth data that is corrected fordepth measurement influencing effects such as stretching/squeezingbecause of gravity effects, temperature effects, pressure differenceeffects, etc.

Apparatus for drilling operations related to this disclosure are nowdiscussed. FIG. 1A shows a schematic diagram of a drilling system 10that includes a drill string 20 having a drilling assembly 90, that mayinclude a bottom hole assembly (BHA), conveyed in a borehole 26penetrating an earth formation 60. The drilling system 10 includes aconventional derrick 11 erected on a floor 12 that supports a rotarytable 14 that is rotated by a prime mover, such as an electric motor(not shown), at a desired rotational speed. The drill string 20 includesa drilling tubular 22, such as a drill pipe, extending downward from therotary table 14 into the borehole 26. A disintegrating device 50 (e.g.,a drill bit), attached to the end of the drilling assembly 90,disintegrates the geological formations to drill the borehole 26.Various types of disintegrating devices can be used. While the presentdisclosure is made with reference to rotary drilling utilizing a rotarydrill bit, other drilling types such as electric pulse drilling, jetdrilling, and/or percussion drilling may be utilized as well. The drillstring 20 is coupled to a drawworks 30 via a kelly joint 21, swivel 28and line 29, e.g., through a pulley and/or pulley system. During thedrilling operations, the drawworks 30 is operated to control the weighton bit, which affects the rate of penetration (ROP). The operation ofthe drawworks 30 is well known in the art and is thus not described indetail herein.

During drilling operations a suitable drilling fluid 31 (also referredto as the “mud”) from a source or mud pit 32 is circulated underpressure through the drill string 20 by a mud pump 34. The drillingfluid 31 passes into the drill string 20 via a desurger and fluidcontrol valve 36, fluid line 38, and the kelly joint 21. The drillingfluid 31 is discharged at the borehole bottom 51 through an opening inthe disintegrating device 50. The drilling fluid 31 circulates upholethrough the annular space 27 between the drill string 20 and theborehole 26 and returns to the mud pit 32 via a return line 35. A sensorS1 in the line 38 provides information about the fluid flow rate. Theflow rate can be controlled by a valve located in or near the pump 34and/or the desurger and fluid control valve 36, or otherwise locatedwithin line 38. A surface torque sensor S2 and a sensor S3 associatedwith the drill string 20 respectively provide information about thetorque and the rotational speed of the drill string. Additionally, oneor more sensors (not shown) associated with line 29 are used to providethe hook load of the drill string 20 and about other desired parametersrelating to the drilling of the wellbore 26. The system may furtherinclude one or more downhole sensors 70 located on the drill string 20and/or the drilling assembly 90. The downhole sensors 70 can include oneor more sensors configured to sense, measure, and/or detect, forexample, a position, orientation, inclination, and/or azimuth of thesensor(s) and/or the BHA or other downhole component. Some or additionalsensors may be configured to detect and/or measure formation propertiesand/or mud properties.

In some applications the disintegrating device 50 is rotated by onlyrotating the drill pipe 22. However, in other applications, a drillingmotor 55 (mud motor) disposed in the drilling assembly 90 is used torotate the disintegrating device 50 and/or to superimpose or supplementthe rotation of the drill string 20. In either case, the rate ofpenetration (ROP) of the disintegrating device 50 into the borehole 26for a given formation and a drilling assembly largely depends upon theweight on bit and the disintegrating device rotational speed. In oneaspect of the embodiment of FIG. 1A, the mud motor 55 is coupled to thedisintegrating device 50 via a drive shaft (not shown) disposed in abearing assembly 57. The mud motor 55 rotates the disintegrating device50 when the drilling fluid 31 passes through the mud motor 55 underpressure. The bearing assembly 57 supports the radial and axial forcesof the disintegrating device 50, the downthrust of the drilling motorand the reactive upward loading from the applied weight on bit. One ormore stabilizers 58 coupled to the bearing assembly 57 and othersuitable locations act as centralizers for the lowermost portion of themud motor assembly and other such suitable locations.

A surface control unit 40 receives signals from the downhole sensors 70and devices, for instance, via a sensor 43 placed in the fluid line 38(in case of a mud pulse telemetry) or elsewhere for other types oftelemetry such as wired pipe telemetry, acoustic telemetry, orelectromagnetic telemetry, as well as from sensors S1, S2, S3, hook loadsensors and any other sensors used in the system and processes suchsignals according to programmed instructions provided to the surfacecontrol unit 40. The surface control unit may process hook positiondata, hook load data, and/or other data such as weight on bit todetermine, derive, or correct drilled distance, ROP, etc. The surfacecontrol unit 40 displays desired drilling parameters and otherinformation on a display/monitor 42 for use by an operator at the rigsite to control the drilling operations. The surface control unit 40contains a computer, memory for storing data, computer programs, modelsand algorithms accessible to a processor in the computer, a recorder,such as tape unit for recording data and other peripherals. The surfacecontrol unit 40 also may include simulation models for use by thecomputer to processes data according to programmed instructions. Thecontrol unit responds to user commands entered through a suitabledevice, such as a keyboard. The control unit 40 is adapted to activatealarms 44 when certain unsafe or undesirable operating conditions occur.

The drilling assembly 90 also contains other sensors and devices ortools for providing a variety of measurements relating to the formationsurrounding the borehole and for drilling the wellbore 26 along adesired path. Such devices may include a device for measuring theformation resistivity near and/or in front of the disintegrating device50, a gamma ray device for measuring the formation gamma ray intensityand devices for determining rotation speed (rpm), inclination, azimuth,ROP, and/or position of the drill string. A formation resistivity tool64, made according an embodiment described herein may be coupled at anysuitable location, including above a lower kick-off subassembly 62, forestimating or determining the resistivity of the formation near or infront of the disintegrating device 50 or at other suitable locations. Aninclinometer 74 and a gamma ray device 76 may be suitably placed forrespectively determining the inclination of the drilling assembly 90and/or BHA and the formation gamma ray intensity. Any suitableinclinometer and gamma ray device may be utilized. In addition, anazimuth device (not shown), such as a magnetometer or a gyroscopicdevice, may be utilized to determine the drill string azimuth. Suchdevices are known in the art and therefore are not described in detailherein. In the above-described exemplary configuration, the mud motor 55transfers power to the disintegrating device 50 via a hollow shaft thatalso enables the drilling fluid to pass from the mud motor 55 to thedisintegrating device 50. In an alternative embodiment of the drillstring 20, the mud motor 55 may be coupled below the resistivitymeasuring device 64 or at any other suitable place.

Still referring to FIG. 1A, other logging-while-drilling (LWD) devices(generally denoted herein by numeral 77), such as devices for measuringformation porosity, permeability, density, rock properties, fluidproperties, etc. may be placed at suitable locations in the drillingassembly 90 for providing information useful for evaluating thesubsurface formations along borehole 26. Such devices may include, butare not limited to, acoustic tools, nuclear tools, nuclear magneticresonance tools and formation testing and sampling tools.

The above-noted devices transmit data to a downhole telemetry system 72,which in turn transmits the received data uphole to the surface controlunit 40. The downhole telemetry system 72 also receives signals and datafrom the surface control unit 40 and transmits such received signals anddata to the appropriate downhole devices (also known as downlink). Inone aspect, a mud pulse telemetry system may be used to communicate databetween the downhole sensors 70 and devices and the surface equipmentduring drilling operations. A transducer 43 placed in the mud supplyline 38 detects the mud pulses responsive to the data transmitted by thedownhole telemetry 72. Transducer 43 generates electrical signals inresponse to the mud pressure variations and transmits such signals via aconductor 45 to the surface control unit 40. In other aspects, any othersuitable telemetry system may be used for two-way data communicationbetween the surface and the drilling assembly 90, including but notlimited to, an acoustic telemetry system, an electro-magnetic telemetrysystem, a wired pipe, or combinations thereof. Repeaters may be used inconjunction with the telemetry system. The wired pipe may be made up byjoining drill pipe sections, wherein each pipe section includes a datacommunication link that runs along the pipe. The data connection betweenthe pipe sections may be made by any suitable method, including but notlimited to, hard electrical or optical connections, induction,capacitive or resonant coupling methods. In case a coiled-tubing is usedas the drill pipe 22, the data communication link may be run along aside of the coiled-tubing.

The drilling system described thus far relates to those drilling systemsthat utilize a drill pipe to convey the drilling assembly 90 into theborehole 26, wherein the weight on bit is controlled from the surface,typically by controlling the operation of the drawworks. However, alarge number of the current drilling systems, especially for drillinghighly deviated and horizontal wellbores, utilize coiled-tubing forconveying the drilling assembly downhole. In such application a thrusteris sometimes deployed in the drill string to provide the desired forceon the disintegrating device. Also, when coiled-tubing is utilized, thetubing is not rotated by a rotary table but instead it is injected intothe wellbore by a suitable injector while the downhole motor, such asmud motor 55, rotates the disintegrating device 50. For offshoredrilling, an offshore rig or a vessel is used to support the drillingequipment, including the drill string.

Still referring to FIG. 1A, a resistivity tool 64 may be provided thatincludes, for example, a plurality of antennas including, for example,transmitters 66 a or 66 b or and receivers 68 a or 68 b. Resistivity canbe one formation property that is of interest in making drillingdecisions. Those of skill in the art will appreciate that otherformation property tools can be employed with or in place of theresistivity tool 64.

As noted above, the drilling fluid 31 is pumped by a drilling fluid pump34 and a flow rate of the drilling fluid is controlled by a desurger anddrilling fluid control valve 36. The drilling fluid pump 34 and flowcontrol valve 36 are controlled by a drilling parameter controller 41and/or the surface control unit 40 to maintain a suitable pressure andflow rate to prevent the borehole 26 from collapsing. The term “drillingfluid” is intended to be inclusive of all types of drilling fluids knownin the art including, but not limited to, oil-based mud, water-basedmud, foam, gas, and air. The drilling parameter controller 41 isconfigured to control, such as by feedback control for example,parameters of drilling equipment used to drill the borehole 26.

One or more surface sensors (e.g., S1, S2, S3, 43) or downhole sensors70 (within drilling assembly 90 and/or along drill string 20) may beused to provide feedback signals to the drilling parameter controller 41for feedback control of drilling equipment. Non-limiting embodiments ofdrilling parameters include weight-on-bit, hook load, torque, drill bitrotational speed (e.g., rpm), rate-of-penetration (ROP), steeringforces, depth, hook position, drill bit position, drilling direction,azimuth, inclination, tool face of the drilling assembly, pressure, mudflow rate, and formation evaluation measurements as described below.Control references, also known as set points, which may include setpoints related to a trajectory plan, can be transmitted to the drillingparameter controller 41 by the control unit 40 (e.g., a computerprocessing system).

In an alternative configuration, the drilling parameter controller 41may utilize, include, comprise, or be part of the control unit 40. Thedrilling parameter controller 41 can be, in some embodiments, installeddownhole, for instance in drilling assembly 90. The drilling parametercontroller 41 can include one or more controlling elements (not shown)configured to deal with various components, features, and/or variablesof the controlling aspects and which can be installed downhole or onsurface or both. One or more stabilizers (not shown) may be disposed atvarious locations on the drill tubular, for instance at one or moredistances L_(i) (i=1, 2, 3 . . . ) from the disintegrating device 50.

As noted, the drilling assembly 90 and/or drill string 20 includes oneor more downhole sensors 70 configured for sensing one or more downholeproperties or parameters related to the earth formation 60, the borehole20, the drilling fluid 31, the drill string 20, the drilling assembly90, etc. Parameters associated with the drilling assembly 90 that may besensed and/or monitored can include, position of the drilling assembly90, orientation of the drilling assembly 90, inclination of the drillingassembly 90, tool face of the drilling assembly 90, and/or azimuth ofthe drilling assembly 90. Sensor data can be transmitted to the surfaceby the telemetry system 72 for processing by the control unit 40.

Data acquisition by the downhole sensor(s) 70 while drilling theborehole 26 may be referred to as measurement-while-drilling (MWD) orlogging-while-drilling (LWD). Sensed data can be correlated to a depthor a time at which the data was obtained to provide a depth-based or atime-based log. One example for a downhole sensor 70 is a formationevaluation sensor which can be a sensor configured to sense gamma-rayradiation. The gamma-ray radiation may be natural or may result fromneutron bombardment of the formation, such as by a pulsed neutrongenerator, a radioactive source, or any other suitable neutron sourceknown in the art. In other embodiments or in combination therewith, thedownhole sensor(s) 70 can include sensors configured to senseresistivity, neutron radiation, acoustic energy, electromagnetic energy,electric energy, magnetic energy, nuclear magnetic resonance properties,chemical properties, formation porosity, formation density, formationpermeability, fluid density, fluid viscosity, temperature, pressure,magnetic fields, force, acceleration, and/or gravity. The downholesensor(s) 70 can comprise active or passive sensing elements. Thedownhole sensors 70 can operate as a part of a sensor system (e.g., aspart of drilling assembly 90) comprising transmitting and receivingelements. The downhole sensor(s) 70 may provide sensed measurements ordata that is measured system output to the drilling parameter controller41 for feedback control purposes.

The drilling assembly 90, as shown, includes a steering system 52. Thesteering system 52 is configured to steer the disintegrating device 50in order to control orientation of the drilling assembly 90 in order toallow drilling the borehole 26 according to a selected path or geometry(for instance, by following a planned geometric path or by keeping adistance to an object). The steering system 52 can control, for example,inclination, azimuth, and/or tool face of the drilling assembly 90.Further, the steering system 52 controls the drilling assembly 90 and/orthe disintegrating device 50 to follow a planned geometric path or bycontrolling the drilling assembly 90 and/or BHA and drill string 20 tokeep a desired distance to or from an object in the earth formation 60.

For steering the drilling assembly 90 or disintegrating device 50, thesteering system 52 includes one or more actuators that are configured toconvert a controller output from the drilling parameter controller 41into a motion that can alter the path being drilled by thedisintegrating device 50. For example in a rotary steering system (RSS),an actuator can be a piston that moves a pad for providing a forceexerted against a borehole wall thus steering the drilling assembly 90and the disintegrating device 50. In an alternative embodiment, steeringthe drilling assembly 90 can be controlled using bent downhole motors(not shown) where behavior can be changed by controlling the motor bentthrough rotating or non-rotating (i.e., sliding) the drill string 20.Bent drilling motors can be used with a fixed bend that cannot be variedduring normal operation or with a variable bend that, for example, canbe varied based on a controller output of the drilling parametercontroller 41. In embodiments with a variable bend, actuators can beincluded in the bent downhole motor that are configured to create orvary the bend, thereby affecting the steering behavior of the steeringsystem.

Accordingly, the term “steering system” is to be construed as includingthose components both downhole and/or at the surface (e.g., rotary table14 and/or drilling fluid pump 34) that operate in order to control atrajectory or orientation of the drill string 20 and/or thedisintegrating device 50 for drilling the borehole 26. It can beappreciated that the output of the control unit 40 and/or the drillingparameter controller 41 can be generated within the steering system 52and does not necessarily need to be received from a source external tothe steering system 52. Accordingly, the term “controller output” is tobe construed as including controller outputs that are received from asource external to the steering system 52 and/or generated internal tothe steering system 52.

In order to provide controller outputs (for example, a control signal ora system input) to the steering system 51 for controlling the trajectoryor orientation of the disintegrating device 50, the drilling parametercontroller 41 is configured to implement a trajectory control algorithm,discussed below. Operation of the trajectory control algorithm employs aprocessor such as in the control unit 40, the drilling parametercontroller 41, and/or other processing system.

In various embodiments, the drilling parameter controller 41 can bedisposed downhole, at the surface, and/or functions can be split betweena surface processor and a downhole processor. Steering commands or othercontroller outputs can be transmitted from the drilling parametercontroller 41 to the steering system 51 by telemetry. In addition, otherinformation of interest (e.g., rate-of-penetration or position, depth,drilled distance, orientation, and/other sensor measurements) can betransmitted using telemetry. Telemetry in one or more embodiments mayinclude mud pulse telemetry, acoustic telemetry, electromagnetictelemetry, telemetry by rpm variations, and/or wired pipe telemetry.Downhole electronics 11 may process data downhole and/or act as aninterface with the telemetry. In other embodiments, the downholeelectronics within the drilling assembly 90 can be configured toimplement the trajectory control algorithm or portions thereof. In suchembodiments, the control unit 40 can transmit a desired trajectory(i.e., trajectory plan) or parts of the trajectory if that is all thatis needed, to the drilling assembly 90, steering system 51, and/ordrilling parameter controller 41. In some embodiments, if the trajectoryis described as a parameterized curve, only the parameters can betransmitted. In non-limiting embodiments, the trajectory can be inabsolute coordinates (such as north-east-down) or the trajectory can bedepth sequence for the orientation (such as inclination, azimuth, toolface), or a distance to an object.

For controlling a system, for instance the drilling system 10 to createa borehole trajectory, a mathematical description of the drilling system10 can be utilized to estimate a potential system output in response toa system input that may comprise a control output. As a non-limitingexample, a mathematical description can be one or more system equations.As used herein, the term “system equation” includes a set of systemequations comprising more than one single equation. Those of skill inthe art will appreciate that there are many types of system equations,and the present disclosure is not limited to any particular systemequation and/or set of system equations. A non-limiting example aresystem equations that are differential equations of the order n. Typicalconventional dynamic systems, known for example from technicalprocesses, can be described with a first order differential equationwith respect to time t:

$\begin{matrix}{\frac{{dy}(t)}{dt} = {f\left( {{y(t)},{u(t)},t} \right)}} & {{Eq}.\mspace{14mu}(1)}\end{matrix}$where y(t) denotes a system output, ƒ(y(t),u(t),t) is a functiondescribing the system behavior and u(t) is the system input that causesthe system output (bold type denoting a vector). The system equation canalso be stated in discrete time-based notation for implementation intoand solution by a digital processor:

$\begin{matrix}{\frac{\left( {{y\left( {k + 1} \right)} - {y(k)}} \right)}{T_{s}} = {g\left( {{y(k)},{u(k)},k} \right)}} & {{Eq}.\mspace{14mu}(2)}\end{matrix}$with a discretization time interval T_(s) and time t_(k)=k T_(s), k=1,2, 3, . . . . The discretization time interval T_(s) can be a fixedvalue or may be variable. The length or the boundaries of thediscretization time interval T_(s) can be predefined. Those skill in theart will appreciated that there are other methods of implementation intoa digital processor known in the art, including, but not limited to, afinite element method that may be utilized accordingly.

Both of the above system equations (Eqs. (1)-(2)) describe a rate ofchange with respect to time. An example is a velocity response of a carwhen stepping on an accelerator pedal. Because the time response to agiven input is known for these systems, discrete time-based controlalgorithms can be designed and parameterized using standard methods asknown in the art. However, there are other systems for which thereaction to a control output cannot be described by a unique functionwith respect to time. For example, in the drilling system 10, the systemoutput (that is, the response or the reaction) of the drilling system 10in response to a steering force applied by an actuator and/or pad of thedrilling assembly 90 to a borehole wall depends significantly on a rateof penetration (ROP) of the drilling system 10. For instance, if the ROPof disintegrating device 50 is zero during a particular time intervalΔt, that is if the drilling assembly 90 does not move in an axialdirection along the borehole 26 during the time interval Δt, a steeringforce applied to the borehole wall by a pad of the drilling assembly 90will not cause any change in the drilling direction. However, incontrast, if the ROP of the drilling system 10 is relatively high, theeffect of that same steering force might lead to a significant change ofthe drilling direction during the time interval Δt.

As explained above, the output of the drilling system 10 in response toa steering control output is a function of spatial position rather thana function of time. Accordingly, the reference for the path or geometryof the borehole 26 being drilled or planned (also known as a “wellplan”) describes the path or geometry with respect to its spatialposition and/or orientation. The spatial position and/or orientation canbe described with respect to depth or drilled distance, rather than withrespect to time.

As described above, a process for controlling a drilling process can beimplemented using the control unit 40 and/or the drilling parametercontroller 41. FIGS. 1B and 3-9 show schematic illustrations of controlsystems in accordance with the present disclosure. FIGS. 1B and 3-9 canbe read and described in representing a physical implementation of acontrol system. Alternatively, FIGS. 1B and 3-9 and their associateddescription can be understood as a framework of modeling packages tosimulate the output of the physical implementations of a control systemand/or parts of a control system. The simulations by these modelingpackages can then be used to adjust a parameter set of a correspondingphysical implementation of the control system and related (e.g.,discrete) control algorithms.

FIG. 1B shows an example schematic illustration of a process that can beimplemented on one of the control unit 40 and/or the drilling parametercontroller 41. As shown, a reference value also referred to as a targetvalue is input at the left side of FIG. 1B. This reference value can becompared to a measured output obtained from sensors (e.g., sensors S1,S2, S3, 43, 70) resulting in a measured error that is input into thecontrol device (e.g., the control unit 40 and/or the drilling parametercontroller 41). The control device (e.g., 40, 41) generates a systeminput that is provided to the system (e.g., drilling system 10) which isthen output as a drilling operation. The system in turn can comprisefurther control loops, such as shown and discussed herein. During thedrilling operation, sensors (e.g., sensors S1, S2, S3, 43, 70) canmonitor aspects of the drilling system 10 and thus generate a measuredoutput that is provided in a feedback loop to the controller (e.g., 40,41), and thus the system input and system output can be activelyadjusted based on the measured features monitored by the sensors (e.g.,sensors S1, S2, S3, 43, 70) to provide an accurate and efficientdrilling operation.

Turning now to FIG. 2 , an example of the geometry of a well plan isschematically shown. The geometry of the borehole 226 is described bythe vector b(s) where s denotes the drilled distance (also known asmeasured depth) along the trajectory as illustrated in FIG. 2 (where i₁,i₂, and i₃ are three orthogonal directions). As a non-limiting example,a system equation that describes the vector b(s) may be a differentialequation of the order n. For example, if n=1, the differential equationdb(s)/ds describing the borehole geometry vector b(s) may be stated asfollows:

$\begin{matrix}{\frac{{db}(s)}{ds} = {F\left( {{b(s)},{b\left( {s - L_{1}} \right)},\ldots\;,{b\left( {s - L_{N}} \right)},{u(s)}} \right)}} & {{Eq}.\mspace{14mu}(3)}\end{matrix}$where F( ) is a function describing the output of the drilling system210 (which may be substantially similar to drilling system 10 of FIG.1A) in response to a control output, i.e., the variation of the vector bin dependence of the drilled distance. u(s) is a system input (e.g., thesteering forces applied by a steering system) that may comprise acontrol output and db(s)/ds is the tangent vector of the trajectory,e.g., at the disintegrating device (e.g., drill bit) describing thedrilling direction.

It can be seen that in this case the system equation (Eq. (3)) is timeindependent. The system equation Eq. 3 depends only on a drilleddistance s along the trajectory. Downhole sensors 70 and/or surfacesensors S1, S2, S3, 43 can be configured to monitor parametersindicative of the drilling direction db(s)/ds such as, but not limitedto, inclination, inclination rate (also known as buildup rate), azimuth,azimuth rate, dogleg severity, depth, drilled distance, ROP, distance toan object, or any combination of these. One or more of the sensedparameters indicative of db(s)/ds may be compared with a reference (alsoknown as set point) that may be part of a well plan. Such comparison canbe made to determine a measurement error (cf. FIG. 1B) to adjust thecontrol output of the drilling parameter controller based on thedepth-based system equation (e.g., feedback loop shown in FIG. 1B). Suchmeasurements and comparisons can be made to minimize the measurementerror as a drilled distance increases. When, for example, a specificsteering force is applied by the steering system of the drilling system210, an inclination response is a function of depth or drilled distancerather than a function of time. The differential equation (Eq. (3))describing the current drilling direction is a delay differentialequation because the drilling direction is also influenced by theposition of stabilizers (not shown) on the BHA and drill string. Thedistances from the disintegrating device to the stabilizers are denotedwith L₁ . . . L_(N) in Eq. (3).

The discretized system equation corresponding to the delay differentialequation for implementation into and solution by a digital processor canbe stated as follows:

$\begin{matrix}{\frac{\left( {{b\left( {k + 1} \right)} - {b(k)}} \right)}{D_{s}} = {G\left( {{b(k)},{b\left( {k - \frac{L_{1}}{D_{s}}} \right)},\ldots\;,{b\left( {k - \frac{L_{N}}{D_{s}}} \right)},{u(k)},k} \right)}} & {{Eq}.\mspace{14mu}(4)}\end{matrix}$with drilled distance s_(k)=kD_(s), k=1, 2, 3, . . . and discretizationdrilled distance interval D_(s). The discretization drilled distanceinterval D_(s) can be a fixed value or can be variable. The length orthe boundaries of the discretization drilled distance interval D_(s), insome embodiments, can be predefined. In one or more embodiments, theselected drilled distance interval D_(s) can be decreased in areas orvolumes of interest in a formation to provide a more accuratetrajectory. Those of skill in the art will appreciate that there may beother methods of implementation into a digital processor, such as afinite element method.

It can be appreciated that discrete depth-based control is onenon-limiting embodiment of what may be described generally as“depth-based control.” In another non-limiting embodiment, depth-basedcontrol may include continuous depth-based control where depth ordrilled distance is continuous or not discretized. Common drillingparameter controllers (e.g., 41 in FIG. 1A) are configured to employdiscrete time-based control algorithms that calculate new controlleroutputs every sampling time interval. The sampling time interval can beidentical to or different from a discretization time interval. Contraryto drilling parameter controllers utilizing a discrete time-based systemequation, drilling parameter controllers utilizing a discretedepth-based system equation calculate new controller outputs everysampling drilled distance interval, at predetermined drilled distances,or at predetermined drilled distance intervals. The sampling drilleddistance interval can be identical to or different from the discretedrilled distance interval. The predetermined drilled distances ordrilled distance intervals at which the drilling parameter controllerutilizing a discrete depth-based system equation to calculate newcontroller outputs might be identical to or different from thepredetermined drilled distances or drilled distance intervals used todefine the discretization drilled distance interval D_(s).

Those of skill in the art will appreciate that the depth-based systemequation (Eq. (3)) could be transformed into a time-based systemequation. A depth-to-time transformation can be accomplished using thefollowing relationship:ds=ROPdt and s=∫ROPdt  Eq. (5)where ROP is rate-of-penetration of the disintegrating device into theearth. From the transformation of Eq. (5), it is seen that if ROP isknown and constant over time, s and t are proportional and thetime-based system equation (Eq. (5)) can be transferred into adepth-based system equation (Eq. (3)) and vice versa. In drillingsystems, however, ROP is usually highly variable and cannot be predictedbecause it depends on many unknown factors such as the geology beingdrilled through and human input from a drilling operator on the surface.

For this reason, the system equation of the drilling system with respectto drilled distance (Eq. (3)) can be well known. However, the systemequation of the drilling system with respect to time (Eq. (5)) may lacknecessary information regarding the time dependency of ROP and istherefore unknown or known only within a relatively broad rangereflecting the range of ROP that the drilling system might experience.Accordingly, the lack of information of the time dependency of the ROPcan lead to relatively high inaccuracies when predicting the output ofthe drilling system in response to a control output of the drillingparameter controller. Consequently, by utilizing a time-based systemequation (e.g., Eq. (5)), the relatively high inaccuracy of the systemequation can lead to improperly calculated controller outputs which inturn can lead to overshoots or undershoots of the output of the drillingsystem that is to be controlled. Repeated improper calculated controlleroutputs can lead to oscillations of the drilling system that are highlyundesired. For example, such oscillations can cause lower overall ROP,deviations from a well plan, higher wear, and generally higher cost.Oscillating well trajectories can also impede the installation ofdownhole equipment after the borehole is drilled, including, but notlimited to, casings, liners, production equipment, etc.

When setting up or designing a time-based control of a drilling systemby a drilling parameter controller, in view of the unknown and/orvariable ROP, it is possible to make assumptions with respect to the ROPof the drilling system during operation. For instance, one possibleassumption is that the ROP will be constant during the operation and setup the controlling parameter accordingly. In that case, the systemequation is accurate and valid for only one particular (assumed) ROP.Thus, a time-based control algorithm based on a system equation is onlyoptimal for a particular (assumed) ROP. Drilling with higher or lowerROP can result in an unstable system or in a suboptimal controlperformance using control systems utilizing time-based system equations.

For example, if several layers of different types of rock are beingdrilled, the ROP can vary due to the different characteristics of thedifferent types of rock. In this type of situation, the control maybecome unstable creating unwanted oscillations of the controlled systemand/or deviations from the planned well trajectory. On the other hand,depth-based control in this type of situation is not dependent on ROPand can provide for stable drilling conditions. Describing the drillingsystem behavior as a unique function of depth or drilled distance allowscommon design methods for conventional control systems (e.g., Nyquist,Hurwitz criteria, Root-locus-plot, etc.) allowing much more accuratecontrol results than if applied to a time-based system equation.

The technical effect of the unknown ROP on a system which is controlledbased on a time-based system equation could be mitigated to some extent(although not eliminated), if the ROP could be measured instantaneouslyand the control output could be adjusted based on the measured ROP.However, measuring the downhole ROP of drilling systems can be difficultdue to a high variability with respect to time, as noted above. Inaddition, the ROP of drilling systems is also not constant with respectto drilled distance. In particular, the ROP measured on surface mightsignificantly differ from the ROP measured downhole. Such differencescan arise from stretching or squeezing effects, temperature effects,pressure differences, and other factors. If telemetry is involved, theinstantaneous determination of ROP can be impeded as the telemetry fromdownhole to surface and vice versa can be too slow for many telemetrysystems such as mud pulse telemetry, acoustic telemetry, electromagnetictelemetry, etc. Further, such telemetry systems can be limited byamounts of data transferred (e.g., in the range of only tens of bits persecond) and/or can be expensive.

Referring now to FIG. 3 , a schematic block diagram of a non-limitingembodiment of a depth-based control system is shown. The depth-basedcontrol system 300 of FIG. 3 implements a well plan 302 which can beinput into a computer or other control device. Various aspects of thedepth-based control system 300 can be implemented, for example, in oneor both of the control unit 40 and/or the drilling parameter controller41 of FIG. 1A. For example, a trajectory control unit 304 that can bepart of a drilling parameter controller 41 is configured to providecontroller outputs (e.g. control signals) to a BHA in a borehole inaccordance with the well plan 302. The well plan 302 can includeinformation about the planned borehole as a function of drilleddistance. The trajectory control unit 304 provides control outputs to aninclination/azimuth control unit 306 for inclination/azimuth control ofthe inclination and/or azimuth of the borehole being drilled.

The inclination/azimuth control unit 306 can receive inclination and/orazimuth feedback from components of a BHA that is performing a drillingoperation. The inclination/azimuth control unit 306 outputs to anactuator control unit 308 (which can be at the surface or downhole) forcontrol of actuators 310 that are located downhole, e.g., as part of aBHA. The actuators 310 are configured to operate on one or more aspectsof a BHA 312, for controlling drilling operations. The BHA 312, in someembodiments, may include a steering system (e.g., steering system 52 ofFIG. 1A). The actuator control unit 308 can receive feedback control toensure a desired position of the actuator 310 is achieved. In someembodiments, a surface top-drive can be used to control the orientationof a mud-motor and thus the trajectory for drilling the borehole, withsimilar control operations and components configured for suchapplication. In some embodiments, the BHA 312 or other parts of thedepth-based control system 300 can receive disturbances that may bedifficult or impossible to control including and/or related but notlimited to BHA design 312 a, torque-on-bit, weight-on-bit 312 b, and/orinformation related to a prior instance well path 312 c.

The design and operational parameters of the BHA 312 determine theforces at the bit and bit orientation. Accordingly, the design andoperational parameters of the BHA 312 may have an effect on thebit-formation interaction 314 that in turn may affect the output of thesystem such as one or more of the ROP and the drilling direction (i.e.,inclination and azimuth). In addition, the bit-formation interaction 314may be affected by disturbances that are difficult or impossible tocontrol during drilling such as, but not limited to, bit properties 314a, formation properties 314 b, and/or drilling constraints 314 c (e.g.,weight-on-bit, torque-on-bit, RPM, flow rate, mud, etc.). Changes in ROP315 and/or the drilling direction will be added together or integratedover a particular depth interval, which is represented by box 316 inFIG. 3B. Adding together or integration of changes in ROP 315 and/ordrilling direction will then lead to an altered position of adisintegrating device (e.g., drill bit; disintegrating device 50 atborehole end 51 in FIG. 1A). The altered position of the disintegratingdevice is then part of the system output 318 of the depth-based controlsystem 300 that is in accordance with the well plan 302.

The depth-based control system 300 is configured to execute adepth-based control algorithm by utilizing a depth-based systemequation, as described above. The depth-based control algorithm, in someembodiments, can be executed every sampling drilled distance interval.That is, controller outputs are updated every time a sampling drilleddistance interval is achieved using a depth-based system equation. Thetrajectory control unit 304 receives to this end information about thedrilled distance, measured depth, or other depth-related data such astrue vertical depth or true stratigraphical depth. This information maybe received from a feedback loop as illustrated in FIG. 3 or form aseparate data source (not shown in FIG. 3 ) as further discussed anddescribed below. In one or more embodiments, the selected samplingdrilled distance interval is approximately one-half meter or one meter.

Non-limiting embodiments of a depth-based control algorithms implementedby the depth-based control system 300 include proportional control,proportional-integral control, and proportional-integral-derivativecontrol. The depth-based control algorithms are configured to reducemeasurement error (cf. FIG. 1B) measured by feedback over drilleddistance by adjusting of a control variable that can be changed bymovement of an actuator, for example. In one or more embodiments,multiple sub-controllers, such as the trajectory control unit 304 and/orthe inclination/azimuth control unit 306 can be incorporated into onecontroller that performs the functions of the multiple sub-controllers.

Those of skill in the art will appreciate that other control designs(e.g. state space control) can be employed without departing from thescope of the present disclosure. Furthermore, the approach fordepth-based control algorithms is independent of the type of thesteering system (e.g., point-the-bit, push-the-bit, rotary steeringsystem, bent motor, etc.).

Control systems that employ depth-based control algorithms as providedherein can include, for example, trajectory control systems (e.g.,controlling a position of a well with respect to a given well plan) ordirection control systems (e.g., controlling inclination or azimuth).There are different depth-based control algorithms that can be used(e.g., PID Control, Model Predictive Control, fuzzy control, etc.)and/or different control architectures that can be used (e.g., directcontrol architecture, subsidiary control architecture, etc.).

In direct control architectures, the output of a trajectory control unitis a target value for a steering unit actuator (e.g., the target forcesfor steering ribs or pads). In subsidiary control architectures (orsecondary control architectures) an outer control loop for a trajectorycontrol unit and an inner loop for a direction (inclination, azimuth)control unit are used. Additional, inner control loops are possible,e.g., a force control for steering pads. The output of an outer controlloop can be a target value for the inner loop. For example, outputs oftrajectory control unit 304 can be target inclination and targetazimuth. The outputs of the inclination/azimuth control unit 306 aretarget forces where for example the output of the force controller maybe target motor currents. In one or more embodiments, if subsidiarycontrol with a depth-based trajectory control as an outer control loopis used, then the inner control loops may not necessarily need to bedepth-based controls. For example, the inner control loop algorithms canbe time-based. As such, a mix of depth-based and time-based controls andalgorithms can be employed for the inner control loops.

Referring now to FIG. 4 , a block diagram of a non-limiting embodimentof a controller implementation using a formation evaluation sensor isillustrated. Control system 400 can include a flow process forcontrolling a drilling operation. The control system 400 includes asensor 402. The sensor 402 can be a formation sensor configured todetect or measure one or more characteristics of a formation 401. Insome non-limiting embodiments, the sensor 402 is ameasurement-while-drilling (MWD) sensor such as a gamma sensor.

The sensor 402 provides a sensor signal 404 output that may be comparedwith a target value that may be part of and/or derived from a well plan406 (e.g., the sensor signal 404 input to a comparison with a targetvalue of the well plan to adjust the input of an inclination/azimuthcontrol unit 410 described below). The target value of the well plan 406and the sensor signal 404 from sensor 402 can be based on variousformation characteristics, such as gamma-ray readings. In such aconfiguration, a formation characteristic control unit 408 can receivethe target value or other input from the well plan 406 and the sensorsignal 404. As such, when the sensor 402 is a gamma-ray sensor, thesensor signal 404 represents a gamma-ray count rate. The formationcharacteristic control unit 408 can be configured to control thedistance from a downhole feature (e.g., cap-rock) that emits gamma-rays.The automatic control can be achieved by controlling the direction ofthe borehole being drilled so that gamma-ray counts are at a constantvalue. To maintain a constant gamma-ray count, the formationcharacteristic control unit 408 can output control signals to aninclination/azimuth control unit 410 and/or an actuator control unit 412that controls an actuator 414. Accordingly, a drilling assembly 416within the formation 401 can be controlled based on a formationcharacteristic and directional drilling in accordance with a well plancan be maintained.

Those of skill in the art will appreciate that other types of sensorscan be used without departing from the scope of the present disclosure.For example, the sensor 402 of FIG. 4 can be an acoustic sensor, amagnetostatic sensor, an electromagnetic sensor, and/or other type ofdownhole sensor. Further, in some embodiments, multiple sensors of thesame type or different types can be used to provide information andfeedback for controlling drilling operations.

The well plan 406 of FIG. 4 may comprise one or more target values thatare selected for the measurement being performed by the sensor 402(e.g., target gamma-ray count value, slope, noise level, etc.). As notedabove, multiple sensors can be employed in various embodiments of thepresent disclosure and the multiple sensors can be configured to measuredifferent properties or parameters of the formation and/or BHA. Forexample, the sensor 402 can be configured to measure resistivity of aformation. As another example, a BHA can have a sensor for measuringgamma-rays and another sensor for measuring resistivity. In suchconfiguration, the gamma-ray measurements can provide a distance tocap-rock while the resistivity measurement provides a distance to anoil-water contact. In some embodiments, the output of more than onesensor can be combined to a single control variable that may be used asa control variable in the formation characteristic control unit 408.

Referring now to FIG. 5 , a block diagram of a non-limiting embodimentof a control system 500 employing a depth-based drilling trajectorycontrol implementation on surface is illustrated. The embodiment shownin FIG. 5 is a distributed depth-based control system 500, i.e., aportion of the control system 500 is located on the surface, indicatedas to the left of the vertical dashed line 501, and a portion of thecontrol system 500 is located downhole, indicated as to the right of thevertical dashed line 501. A well plan 502 can be input into a surfacecontrol unit 504 (e.g., similar to control unit 40 of FIG. 1A). Thesurface control unit 504 can be utilized to automatically,semi-automatically, or manually vary parameters of the drilling systemvia a rig control unit 506 and also be in communication with downholecomponents (e.g., the BHA and components thereof) through a downlinksystem 508. The surface control unit 504 can receive surface or downholeinformation and/or data at a data processor 510. Surface or downholeinformation or data may include depth of a reference location on thedrilling assembly. Downhole data or information may be provided throughtelemetry 512 and/or other data communication means or mechanism. Thedata processor 510 can generate input data 514 by processing thedownhole information and/or surface information (e.g., mud, ROP, surveyinformation, depth, drilling direction, vibration, rpm, weight-on-bit,torque-on-bit). Information and/or data may comprise measuredinformation and/or data or simulated information and/or data, etc. Theinput data 514 can be used to determine deviations or measurement errorsfrom reference values (cf. FIG. 1B) that may be part of the well plan502.

The control output or measurement error (e.g., control signals from thesurface control unit 504) can be used to control downhole componentsincluding, but not limited to, an inclination/azimuth control unit 516and/or an actuator control unit 518 that controls one or more actuators520. Controlling the control units 516, 518 may include modifyingcontrol modes and/or parameterization of control algorithms implementedin the control unit 516 and/or control unit 518. Further, the controloutput from the surface control unit 504 can be used to influence and/orcontrol a BHA 522, a bit-formation interaction 524, and/or the adding orintegration 526 over a particular depth interval (similar to thatdescribed above with respect to FIG. 3 ). Further, similar feedbackloops described and shown above can be utilized in the control system500. The control system 500 can implement changes at the surface (e.g.,advice change to plan, advice to ream, advice to change bit and/or BHAdesign, etc.). Additionally, additional information and actions can betranslated or transmitted from the surface, including, but not limitedto, surface control of weight-on-bit, RPM, flow rates, mud properties,etc. that can be implemented through the rig control unit 506.Similarly, the downlink 508 can be used to send control updates and/orchanges to downhole components, including the BHA (e.g., changing activebit features, changes in control mode, controller, and/orparameterization, etc.).

An advantage of implementation of the distributed depth-based controlsystem, as shown in FIG. 5 , is that all information required fordepth-based trajectory control is available at the surface onconventional drilling systems or can be easily derived (e.g., referencetrajectory, information about current position such as from a survey,depth, drilled distance, etc.). Furthermore, depth-based control onsurface can make easier use of surface actuation (e.g., weight-on-bit,rotational speed, mud flow rate, etc.) in order to influence a drillingtrajectory or change constraints such as, but not limited to,disturbances 312 a, 312 b, 312 c, or drilling constraints 314 c.

In the embodiment of FIG. 5 , the surface control unit 504 can receivedrilling direction information from downhole components. For example,the drilling direction information can be obtained from the BHA 522 orother downhole components via telemetry 512 and/or from surfaceinformation such as survey information. In addition, the surface controlunit 504 can receive the well plan 502. Using this information, thesurface control unit 504 can provide control outputs, drillingconstraints, or disturbances (such as 312 a, 312 b, 312 c in FIG. 3 )downhole via the downlink 508 and surface control signals to surfacedrilling equipment (e.g. rig control unit 506) for controllingweight-on-bit, rotational speed, mud flow rate, mud properties, etc. Thesignals sent downhole can be configured to switch the BHA into adifferent operational mode, change downhole control algorithms, changecontrol parameterization, etc. The signals sent downhole may also beconfigured to activate or influence active BHA devices (e.g., activebit, reamer, additional stabilizers, and/or other mechanical propertiesof the BHA which could be actuated) via downlink 508. The surfacecontrol unit 504 may also be configured to provide advice to a user whena parameter does not meet or exceed a threshold value or, alternatively,exceeds a threshold value depending on the parameter. For example, ifthe ROP does not meet a selected value, the surface control unit 504 canissue a suggestion to change the disintegrating device or to change theBHA. Other advice may include a suggestion to change a drilling plan, toream the borehole, or to change a previous borehole path. Alternatively,an automatic or semi-automatic ROP optimization process can be applied.

Referring now to FIG. 6 , a block diagram of a non-limiting embodimentof a control system 600 employing a depth-based control implementationdownhole is illustrated. The embodiment in FIG. 6 is a distributeddepth-based control system, i.e., a portion of the control system 600 islocated on the surface, indicated as to the left of the vertical dashedline 601, and a portion of the control system 600 is located downhole,indicated as to the right of the vertical dashed line 601. The controlsystem 600 includes a well plan 602 and a downhole control unit 604(e.g., downhole electronics and/or a combination with surface anddownhole electronics). The control system 600 further includes a rigcontrol unit 606 and communication is enabled with downhole components(e.g., a BHA and components thereof) through a downlink system 608. Adata processor 610 located on the surface can receive information and/ordata through telemetry 612 and/or other data communication means ormechanism. In particular, the data processor 610 can receive depthinformation or depth related information such as number and length ofdrilling tubulars and hook position. Such information allows the systemto calculate drilled distance that is required to apply the depth-basedcontrol algorithm described above. The data processor 610 can generatefurther input data 614 by processing downhole information and/or surfaceinformation (e.g., mud properties, flow rate, ROP, survey information,drilling states, etc.). The input data can be measured data, simulateddata, or both. The input data 614 can be used to update and/or otherwisemodify the well plan 602.

The downhole control unit 604 can be used to control downhole componentsincluding, but not limited to, an inclination/azimuth control unit 616and/or an actuator control unit 618 that controls one or more actuators620 in the BHA 622. Further, the control signals from the downholecontrol unit 604 can be used to influence and/or control other parts ofthe BHA 622, the bit-formation interaction 624, and/or theadding/integration 626 over a particular depth interval (similar to thatdescribed above with respect to FIG. 3 ). Further, similar feedbackloops described and shown above can be utilized in the control system600. The control system 600 can implement changes at the surface (e.g.,advice change to plan, advice to ream, advice to change bit and/or BHAdesign, etc. via data processor 610 or downlink system 608).Additionally, additional information and actions can be translated ortransmitted to the surface, including, but not limited to, surfacecontrol of weight-on-bit, RPM, flow rates, mud properties, etc. that canbe implemented through the rig control unit 606. Similarly, the downlinksystem 608 can be used to send control updates and/or changes todownhole components, including the BHA (e.g., changing active bitfeatures, changes in control mode, controller scheme, and/orparameterization of the control system, etc.).

Depth-based downhole trajectory control as enabled in control system 600employs information about ROP or a depth or drilled distance increment.These values are typically measured on surface in conventional rigs andcan be transmitted downhole from the surface via downlink system 608,telemetry 612 using wired drill pipe, mud pulse telemetry, acoustictelemetry, electromagnetic telemetry, rpm variations, etc. In someapplication, however, it may be possible to measure depth, drilleddistance, or ROP downhole and convey such information directly or viadata processor(s) to the control units 604. Sensors and/or algorithms todetermine depth and position related information such as drilleddistance or drilling orientation are represented by element 628 in FIG.6 . Information (e.g., change in rotational speed, mud flow rate, etc.)can be transmitted downhole every drilled depth increment (e.g., everydrilled meter). In some embodiments, the rotational speed (rpm) or mudflow rate can be changed every drilled depth increment. With thisconcept, information can be sent to the downhole tool (e.g., BHA 622,etc.) that a depth increment has been drilled. In some embodiments, forexample when using an autodriller in constant ROP mode, the ROPtypically stays constant over a long period of time and may bedownlinked through downlink system 608 to the downhole control unit 604.The downhole control unit 604, in some embodiments, can be configured toevaluate a latest received ROP and switch control parameterizations asneeded.

In embodiments such as shown with control system 600 in FIG. 6 , surfacecontrol does not necessarily need to be a classic control loop. Thecontrol system 600 can include surface control aspects that automatesome or all trajectory drilling related tasks (e.g., taking surveys,sending downlinks, changing rig set points, etc.). Some control loopswhich require downhole measurements (e.g., inclination-, azimuth-, oractuator-control) may be easier to implement downhole. For this reason,the control system 600, in some embodiments, can be a distributedcontrol system in which some control functions are performed at thesurface and other control functions are performed downhole, as shown inFIG. 6 . Further, control features such as reference variable splines,discussed below, allow distribution of trajectory control whileminimizing a number of downlinks.

Referring to FIG. 7 , a block diagram of a control system 700 embodimentof a surface controller 704 implementation using one or more referencevalues (e.g., target inclination) is illustrated. A well plan 702 can beinput to the surface control unit 704 which can output control output tobe transmitted to various downhole components (e.g., BHA). The surfaceand downhole components are separated in FIG. 7 by vertical dashed line701. The downhole components can include, but are not limited to, aninclination/azimuth control unit 710, an actuator control unit 712 thatcontrols an actuator 714, and/or a drilling assembly 716. Those of skillin the art will appreciate that additional and/or other componentsand/or various feedback loops and/or other inputs can be employedwithout departing from the scope of the present disclosure.

In this non-limiting embodiment, information 718, like a set ofpolynomial parameters, can be output from the surface control unit 704and sent to a target value generator 720 (e.g., target values for aspline, a ramp, or any other parameterized curve). The target valuegenerator 720 is used to generate target values employed as referenceinput for the control system 700 to have a depth or drilleddistance-dependent reference value. System outputs are then referencedagainst the depth or drilled distance-dependent target or referencevalue (e.g., to minimize the difference between a controlled parameterand the target value). Advantageously, embodiments such as controlsystem 700 enable, for example, features such as soft landing, complexwell paths with a minimum number of downlinks, etc.

For example, as enabled by control system 700, only the parameters of areference trajectory need to be downlinked. That is, as shown in FIG. 7, the surface control unit 704 can provide a parameterized curve, theparameter of which included information 718, to the target valuegenerator 720. The target value generator 720 can thus provide one ormore reference values to one or more of the various units downhole(e.g., units 710, 712, 716, etc.).

In one or more embodiments, because a target-trajectory can be known inadvance, a pre-control or pre-filter can be used as illustrated in FIG.8 . The control system 800 is a subpart of a control system similar tothose described above, and thus various features are omitted forsimplicity. In control system 800 a control unit 804 (on surface ordownhole) can provide control signals to one or more downhole toolsand/or devices 830 (which may include a BHA including a steering unit,and/or other units as described herein or as known in the art). Thecontrol unit 804 can receive target values 832 as input, with the targetvalues 832 being passed through a pre-filter 834 and/or a pre-controlunit 836. As shown, the downhole tools and/or devices 830 can be subjectto disturbances 838, as discussed above, and further can makemeasurements 840 which can be looped back into the control system 800through a feedback loop.

Such a filter configuration (e.g., pre-filter 834) can add a degree offreedom and allows optimization of a disturbance transfer function and areference transfer function independently. The disturbance transferfunction describes how the control system 800 reacts on disturbances838. For example, how long it takes until a control error (deviationfrom well plan) is eliminated. In a room heating example, a disturbanceis opening of a window. The disturbance transfer function describes howfast a temperature controller for the room can adjust the heater tocompensate for the open window. The reference transfer functiondescribes how the control system 800 reacts if the target values 832 arechanged. That is, how long it takes to get to the new set-point. In theroom heating example, if a user changes a desired room temperature from18° C. to 20° C., the reference transfer function describes how long ittakes until the room temperature is 20° C. This also allows anticipatingchanges in a reference trajectory which could be advantageous forfeatures like soft-landing.

Further, a discrete depth-based control system can simplify the designof the pre-control unit 836. Pre-control unit 836 can be based onknowledge or analysis of the control system 800. For example, if it isknown that it requires 50% force to achieve a build-up rate of 10°/100ft, then the pre-control unit 836 can directly apply that force when itis desired to have a build-up rate of 10°/100 ft. The control unit 804now only needs to compensate for control errors. The pre-filter 834 canprovide for changing control variables such as to provide fasterreaction to changes in target values 832. For example, in the roomheating example, suppose it is desired to increase room temperature from18° C. to 20° C. This is a step of 2° C. which would, for example,require the heater to increase power by 100 W. In order to speed up theheating, a pre-filter could be used which changes the 2° step to atarget temperature of 30° C. for 30 minutes and then to 20° C.Accordingly, the heater could increase power by 500 W for the first 30minutes and then 100 W for the rest of the time. Accordingly, as will beappreciated by those of skill in the art, the pre-filter 834 andpre-control unit 836 can provide improvement to an overall controlsystem, as provided herein.

In one or more embodiments, discrete depth-based control may use a modelpredictive control unit as illustrated in FIG. 9 . A model predictivecontrol unit 950 solves an optimization problem every discretizationdrilled distance interval (i.e., every selected drilled distanceinterval). The optimization may be based on a drill-ahead model thatincludes target values 932 of a control system 900 to predict howdownhole tools and/or devices 930 may react on input parameter changes.The optimization problem may also consider costs for downlinks, theoptimal time when to send a downlink, which actuator to use forinfluencing a desired trajectory, etc. Furthermore switching betweenseveral optimization objectives (e.g., drill as fast as possible, drillwith minimum wear, control hold distance to formation layer, etc.) maybe implemented. Because the optimization is dependent on a model, someadaptation mechanisms may be used. For example, downhole measurements940 may be used to update model parameters within the model predictivecontrol unit 950, as shown.

Another potential effect which has a significant influence on thetrajectory control of a steering unit and/or BHA can be a time lag ortime delay of sensor signals. Because directional and formationevaluation sensors are traditionally mounted several meters behind thedisintegrating device, the information about changes in the drilledtrajectory is measured with a delay relative to the actual change. Thatis, downhole sensors can only sense a change once they have reached thechange, and thus the disintegrating device has moved further into thetrajectory. The time difference of the time when the disintegratingdevice reaches a change and the time a downhole sensor sense the changeis highly dependent on ROP which is usually not constant and notpredictable as it depends on many factors, some of which are difficultor impossible to control. This can result in a suboptimal controlperformance and can lead to an unstable control resulting in boreholeundulations. When using a discrete depth-based control algorithm, asprovided herein, a depth-delay between disintegrating device and sensoris constant and can be compensated quite easily through a constant delayelement for the trajectory plan before comparison with the actualposition. The offset-compensation may also be based on a drill tubularmodel and/or may use additional sensor information (e.g., derived frombending moment sensors in the BHA).

Exceptions to discrete depth-based control may be handled by procedures.There are several drilling situations where an automated trajectorycontrol system is presumably not working (e.g., reaming, drilling on astringer, etc.). These situations may be detected and covered byelectronic procedures which advise (or automatically apply) optimalset-points for the current situation.

An appropriate control approach for a current situation may be selectedby automatically switching between different control approaches, controlparameterizations, and/or other control concepts (e.g., electronicprocedures). Electronic procedures may be used to supervise the controland switch control laws, if required.

FIG. 10 is a flow process for one non-limiting example of a process 1000for controlling a trajectory of a borehole being drilled into the earth.The process 1000 can be performed with drilling systems and/or controlsystems as shown and described above. Various components may be locatedon the surface while other components may be located downhole, such asdescribed in various embodiments above. Those of skill in the art willappreciate that the above described embodiments and configurations arenot to be limiting, and the process 1000 can be performed by otherdrilling systems as known in the art.

Block 1002 calls for drilling a borehole with a drilling system having adrill tubular and a disintegrating device coupled to the drill tubular.

Block 1004 calls for steering the disintegrating device using a steeringsystem coupled to the drill tubular and configured to receive steeringcontrol outputs/steering system inputs in order to steer thedisintegrating device. As noted above, the steering system is inclusiveof components that are configured to receive a steering controloutputs/steering system inputs and influence the trajectory and/ororientation of the drill tubular and thus the disintegrating deviceaccording to the steering control outputs/steering system inputs inorder to drill the borehole in a predictable manner. The components mayinclude downhole components such as a rotary steering system and/orsurface components such as a top-drive or mud pump.

Block 1006 calls for providing steering control outputs/steering systeminputs to the steering system using a control unit configured to providedepth-based control (e.g., as described above). For example, a controlalgorithm can be employed and provided having a mathematical modeldescribing behavior of the drilling operation (e.g., the steeringsystem) as a function of drilled distance.

The flow process 1000 can also include a step of receiving a position,orientation, inclination, and/or azimuth of a BHA. The BHA is coupled tothe drill tubular and can provide feedback signals from the drillingsystem. For example, sensors disposed on the BHA can detect and/ormeasure position, orientation, inclination, and/or azimuth of the BHA assensed data. The sensed data can be sent to the control unit of thedrilling system (either on the surface or downhole). In one or moreembodiments, the sensors are configured to sense a position of the BHAand the flow process 1000 will further include correcting the positionof the BHA to provide a position of the disintegrating device.

The flow process 1000, in some embodiments, can also include controllingan actuator in a steering system to control a trajectory of the boreholebeing drilled. In one or more embodiments, the actuator is coupled to apad of a rotary steering system. The pad can contact a wall of theborehole and apply force thereto to steer the disintegrating device inaccordance with control signals from the control system.

The flow process 1000, in some embodiments, can also include formationparameter or characteristic information. For example, the flow process1000 may further include a process of sensing a parameter of a formationusing a formation evaluation sensor or tool disposed on the drilltubular. A formation evaluation feedback signal can then be sent fromthe formation evaluation sensor or tool to the controller or a controlunit. The flow process 1000 can further include controlling a drillingtrajectory to maintain a distance from, for example, formation caprocks, formation layers, oil-water contacts, a formation layer, aformation layer boundary, etc. within a selected range of distance,using the formation evaluation feedback signal from the formationevaluation sensors or tools.

The flow process 1000 can also include correcting a received BHA ordisintegrating device (e.g., drill bit) position derived from data or asensor in order to account for bending of the drill tubular in theborehole or stretching/squeezing of the drill tubular due to the forceof gravity, pressure differences, temperatures, etc. acting on thedrilling assembly and drill tubular.

In support of the teachings herein, various analysis components may beused, including a digital and/or an analog system. For example, thedownhole electronics, the computer processing systems, the downholesensors, the drilling/production parameter controllers, the steeringsystems, the actuators and/or other components discussed herein mayinclude digital and/or analog systems. Further, the systems andconfigurations described herein may have components such as processors,storage media, memory, inputs, outputs, communications links (e.g.,wired, wireless, pulsed mud, optical, acoustic, electromagnetic, etc.),user interfaces (e.g., display, printer, etc.), software programs,signal processors (e.g., digital, analog) and other such components(e.g., resistors, capacitors, inductors, etc.) to provide for operationand analyses of the apparatus and processes disclosed herein in any ofseveral manners well-appreciated in the art. It is considered that theseteachings may be, but need not be, implemented in conjunction with a setof computer executable instructions stored on a non-transitory computerreadable medium, including memory (ROMs, RAMs), optical (CD-ROMs), ormagnetic (disks, hard drives), or any other type that when executedcauses a computer to implement the method of the present disclosure.These instructions may provide for equipment operation, control, datacollection and analysis and other functions deemed relevant by a systemdesigner, owner, user or other such personnel, in addition to thefunctions described in this disclosure.

Embodiment 1

An apparatus for controlling a trajectory of a borehole being drilledinto the earth, the apparatus comprising: a drilling system including adrill tubular, a disintegrating device, and a steering system coupled tothe drill tubular configured to steer the drilling system, the drillingsystem configured to drill the borehole by receiving control outputsfrom at least one control unit for controlling parameters of thedrilling system, the at least one control unit configured to provide thecontrol outputs to the steering system, the at least one control unitbeing configured to provide depth-based control.

Embodiment 2

The apparatus according to any of the preceding embodiments, wherein thecontrol unit receives and uses data indicative of measured depth toprovide the depth-based control.

Embodiment 3

The apparatus according to any of the preceding embodiments, wherein thedata indicative of measured depth is generated at the earth's surface orderived from data generated at the earth's surface.

Embodiment 4

The apparatus according to any of the preceding embodiments, wherein thecontrol unit comprises a trajectory control unit configured to control atrajectory of the borehole being drilled and/or an inclination/azimuthcontrol unit configured to control the inclination and/or an azimuth ofthe borehole being drilled.

Embodiment 5

The apparatus according to any of the preceding embodiments, wherein atleast one of the trajectory control unit or the inclination/azimuthcontrol unit is located downhole.

Embodiment 6

The apparatus according to any of the preceding embodiments, furthercomprising at least one sensor coupled to the drilling system andconfigured to measure data indicative of a position, orientation,inclination, and/or azimuth of the sensor and provide the measured datato the at least one control unit.

Embodiment 7

The apparatus according to any of the preceding embodiments, wherein thetrajectory control unit is configured to provide a control output to theinclination/azimuth control unit and the inclination/azimuth controlunit is configured to receive the sensed data indicative of inclinationand/or azimuth.

Embodiment 8

The apparatus according to any of the preceding embodiments, furthercomprising at least one actuator control unit configured to control atleast one actuator, the at least one actuator configured to change atleast one drilling parameter of the drilling system, the at least oneactuator control unit receiving control outputs from the control unit.

Embodiment 9

The apparatus according to any of the preceding embodiments, wherein theactuator is coupled to a pad of a rotary steering system configured tocontact a wall of the borehole for steering the drilling system.

Embodiment 10

The apparatus according to any of the preceding embodiments, wherein theactuator is coupled to a bent motor system, the actuator configured tochange the bent of the motor.

Embodiment 11

The apparatus according to any of the preceding embodiments, furthercomprising at least one formation evaluation sensor disposed on thedrilling system and configured to sense a parameter of a formation, theformation evaluation sensor configured to provide the sensed parameterto the at least one control unit

Embodiment 12

The apparatus according to any of the preceding embodiments, wherein theat least one formation evaluation sensor comprises at least one of agamma-ray detector, a resistivity sensor, an acoustic sensor, an NMRsensor, or a nuclear sensor.

Embodiment 13

A method for controlling a trajectory of a borehole being drilled intothe earth, the method comprising: drilling a borehole with a drillingsystem comprising a drill tubular and disintegrating device coupled tothe drill tubular; and steering the disintegrating device with asteering system coupled to the drill tubular and configured to receivesteering control outputs from at least one control unit in order tosteer the disintegrating device, the at least one control unitconfigured to provide depth-based control.

Embodiment 14

The method according to any of the preceding embodiments, wherein thecontrol unit receives and uses data indicative of measured depth toprovide the depth-based control.

Embodiment 15

The method according to any of the preceding embodiments, furthercomprising generating the data indicative of measured depth is generatedat the earth's surface or derived from data generated at the earth'ssurface.

Embodiment 16

The method according to any of the preceding embodiments, furthercomprising receiving with the at least one control unit data indicativeof at least one of a depth, position, orientation, inclination, and/orazimuth of a bottom hole assembly (BHA) coupled to the drill tubular.

Embodiment 17

The method according to any of the preceding embodiments, wherein the atleast one control unit comprises a trajectory control unit configured tocontrol a trajectory of the borehole being drilled and/or aninclination/azimuth control unit configured to control the inclinationand/or azimuth of the borehole being drilled.

Embodiment 18

The method according to any of the preceding embodiments, furthercomprising controlling an actuator in the steering system in order tocontrol the trajectory of the borehole being drilled.

Embodiment 19

The method according to any of the preceding embodiments, furthercomprising (i) sensing a parameter of a formation using a formationevaluation sensor disposed on the drilling system and (ii) providing asignal indicative of a measured output from the formation evaluationsensor to the at least one control unit.

Embodiment 20

The method according to any of the preceding embodiments, furthercomprising identifying at least one formation feature by using theparameter of a formation and controlling by the at least one controlunit the steering system to maintain a distance from the at least oneformation feature.

Elements of the embodiments have been introduced with either thearticles “a” or “an.” The articles are intended to mean that there areone or more of the elements. The terms “including” and “having” areintended to be inclusive such that there may be additional elementsother than the elements listed. The conjunction “or” when used with alist of at least two terms is intended to mean any term or combinationof terms. The term “configured” relates to one or more structurallimitations of a device that are required for the device to perform thefunction or operation for which the device is configured.

The flow diagrams and schematic diagrams depicted herein are justexamples. There may be many variations to these diagrams or the steps(or operations) described therein without departing from the presentdisclosure. For instance, the steps may be performed in a differingorder, or steps may be added, deleted or modified. All of thesevariations are considered a part of the claims appended herewith.

While one or more embodiments have been shown and described,modifications and substitutions may be made thereto without departingfrom the present disclosure. Accordingly, it is to be understood thatthe present disclosure has been described by way of illustrations andnot limitation.

It will be recognized that the various components or technologies mayprovide certain necessary or beneficial functionality or features.Accordingly, these functions and features as may be needed in support ofthe appended claims and variations thereof, are recognized as beinginherently included as a part of the teachings herein and a part of theembodiments disclosed and/or variations thereof.

While the present disclosure has been described with reference tonon-limiting, example embodiments, it will be understood that variouschanges may be made and equivalents may be substituted for elementsthereof without departing from the scope of the present disclosure. Inaddition, many modifications will be appreciated to adapt a particularinstrument, situation or material to the teachings of the presentdisclosure without departing from the essential scope thereof.Therefore, it is intended that the claims not be limited to theparticular embodiment(s) disclosed as the best mode contemplated forcarrying out the concepts herein, but will include all embodimentsfalling within the scope of the appended claims.

What is claimed is:
 1. An apparatus for controlling a trajectory of aborehole being drilled into the earth, the apparatus comprising: adrilling system including a drill tubular, a disintegrating device, anda steering system coupled to the drill tubular configured to steer thedrilling system, the drilling system configured to drill the borehole byreceiving control outputs from at least one control unit for controllingparameters of the drilling system, the at least one control unitconfigured to provide the control outputs to the steering system, the atleast one control unit being configured to provide a depth-based controloutput, wherein the depth-based control output is calculated based on adepth-based system equation every time at least one of a predetermineddrilled distance and a predetermined drilled distance interval isachieved; at least one sensor coupled to the drilling system andconfigured to measure data indicative of a position, orientation,inclination, and/or azimuth of the sensor and provide the measured datato the at least one control unit.
 2. A method for controlling atrajectory of a borehole being drilled into the earth, the methodcomprising: drilling the borehole with a drilling system comprising adrill tubular and disintegrating device coupled to the drill tubular;and steering the disintegrating device with a steering system coupled tothe drill tubular and configured to receive steering control outputsfrom at least one control unit in order to steer the disintegratingdevice, the at least one control unit configured to provide adepth-based control output, wherein the depth-based control output iscalculated based on a depth-based system equation every time at leastone of a predetermined drilled distance and a predetermined drilleddistance interval is achieved.
 3. The method according to claim 2,wherein the control unit receives and uses data indicative of measureddepth to provide the depth-based control output.
 4. The method accordingto claim 3, further comprising generating the data indicative ofmeasured depth is generated at the earth's surface or derived from datagenerated at the earth's surface.
 5. The method according to claim 2,further comprising receiving with the at least one control unit dataindicative of at least one of a depth, position, orientation,inclination, and/or azimuth of a bottom hole assembly (BHA) coupled tothe drill tubular.
 6. The method according to claim 2, wherein thedepth-based control output is independent of a rate of penetration. 7.The method according to claim 2, further comprising controlling anactuator in the steering system in order to control the trajectory ofthe borehole being drilled.
 8. The method according to claim 2, furthercomprising (i) sensing a parameter of a formation using a formationevaluation sensor disposed on the drilling system and (ii) providing asignal indicative of a measured output from the formation evaluationsensor to the at least one control unit.
 9. The method according toclaim 8, further comprising identifying at least one formation featureby using the parameter of a formation and controlling by the at leastone control unit the steering system to maintain a distance from the atleast one formation feature.